1. Field of the Invention
The present invention relates to processes for improved operation of coal-fired and other carbonaceous fuel-fired industrial and electrical utility boilers, incinerators, and high temperature combustion reactors. More particularly, the present invention relates to cost-effective processes for reducing undesirable and noxious stack emissions from coal-fired and other carbonaceous-fuel-fired combustion systems, for reducing the fouling of combustion system components, for reducing the emissions of acid and of greenhouse gases (GHG's), CO2 and H2O, and for reducing corrosion within such combustion systems.
2. Description of the Related Art
In coal-fired power generating plants, as well as in other industrial processes involving the combustion of carbonaceous fuels, a number of the products of the combustion process include compounds that have an adverse influence on boiler operation, or the compounds are environmentally undesirable and the discharge of which into the environment is subject to environmental regulations. Such compounds include sulfur oxides (SOx), nitrogen oxides (NOx), hydrochloric acid, and such heavy metals as mercury, arsenic, lead, selenium, and cadmium. Additionally, a significant number of nations, including the European Union and Japan, have taken steps to further limit the emissions of carbon dioxide (CO2). Similar steps have been proposed in the United States but are currently being implemented by few of the 50 states. Water vapor is also perceived to be a GHG, but to date there have been no proposals to regulate emission levels.
In order to meet environmental limitations affecting the discharge into the atmosphere of the most prevalent of the most widely regulated compounds, sulfur dioxide (SO2), combustion products from such plants and processes are commonly passed through capital-intensive flue gas desulfurization (FGD) systems, which are downstream from the furnace and tend to be economically feasible only on newer, larger combustion systems. The treatment of flue gases to capture SO2 is often effected in lime- or limestone-based wet scrubbers, in which lime or limestone slurries are introduced into the flue gas stream to contact the flue gases before they are discharged into the atmosphere. The SO2 is chemically converted in the scrubbers into insoluble calcium compounds in the form of calcium sulfites or calcium sulfates. The SO2 contained in such combustion products is thus converted into less-environmentally-harmful compounds that either are disposed of in landfills, or, when suitably modified or treated, are sold as marketable chemicals as a result of their conversion into marketable gypsum. Interest in exploration of “dry scrubbers” is increasing because the wet systems produce a liquid by-product stream that requires treatment before discharging. The dry systems are somewhat less capital intensive than wet processes and treat the flue gas upstream of the dust collectors.
Although useful for converting some of the sulfur oxides, the widely-used types of wet lime/limestone scrubbers are not very effective in capturing the 1% to 1.5% of the sulfur in the fuel that is transformed during the combustion process into gaseous sulfur trioxide (SO3), most of which can escape from the scrubbers. The SO3 that is discharged poses environmental problems in that unless it is captured or transformed, the SO3 results in a persistent, visible plume in the form of a corrosive and a potentially hazardous sulfuric acid mist. The historic solution to the SO3 operational problems has been to minimize them by discharging the flue gas at temperatures above the acid dew point in the 300° F. to 340° F. range, which involves not utilizing as much as 5% of the energy in the fuel.
Further complicating the SO3 capture problem, selective catalytic reactors (SCR's), which are installed primarily in the larger, newer plants to comply with nitrogen oxide emission regulations, essentially cause a doubling of the amount of SO3 that is generated. Consequently, the already serious operational and environmental problems caused by the presence of SO3 are magnified. Further, a new fouling problem within the SCR's is created in the form of sticky ammonium bisulfate deposits. In that regard, the slight excess of NH3 used within the SCR's to eliminate NOx reacts with the SO3 to form the sticky ammonium bisulfate. The historically applied solution for minimizing SO3 by discharging the flue gases above the acid dew point also results in the emission of additional CO2, the greenhouse gas the discharge of which is regulated in some parts of the nation and the world. That solution to minimizing the SO3 problems burns as much as 5% more fuel to generate useful energy.
The SO3 emission problem has been addressed chemically using a variety of alkaline chemicals (wet and dry), including lime hydrate, limestone, MgO, Mg(OH)2, and Trona, that are injected into the system at different intermediate and downstream points in the flue gas flow path. For example, lime or limestone injected near the exit of the radiant furnace to capture SO2 can be effective in capturing essentially all of the SO3, because such a large excess of lime or limestone is needed to scavenge the SO2, and because the SO3 is more readily captured by those chemicals. The MgO and Mg(OH)2 are effective in capturing SO3, but are ineffective in scavenging SO2. To avoid contributing to slagging problems the sodium-based additives are only applied downstream. However, the commercial −325 mesh powders that are generally utilized, which have a median particle size of about 20 microns when injected into the upper furnace, tend to magnify boiler tube ash deposit problems, and they also increase the quantity of particulates that are discharged from the boiler and that can escape through the electrostatic precipitators (ESP's). The deposit problems are the result of the 20 micron-size particles impacting the boiler tubes and other furnace inner surfaces, while the finer particles, about 5 micron size or finer, act like gas molecules and tend to flow around the boiler tubes, to thereby avoid impact with and to bypass the boiler tubes.
The unfavorable particle collection efficiency in the electrostatic precipitators when −325 mesh lime or limestone is injected at the boiler exit is a result of the poor electrical properties of unreacted CaO that is not collected. The presence of unreacted CaO results from the high stoichiometric ratios of the treatment chemicals that are needed when utilizing the relatively coarse −325 size powders. The same particulate collection and discharge problem is also encountered when lime or lime hydrate is injected in powder form into the lower temperature region of the flue gas path downstream of the furnace. On systems including scrubbers for capturing particulates, the precipitator problem can be circumvented by injecting the lime downstream of the precipitator. However, the downstream distribution of the relatively coarse −325 mesh powders results in relatively inefficient SO3 capture, necessitating dosage at several times stoichiometric. Further, the injection downstream of the ESP of slurries that include micron-sized particles pose serious problems due to insufficient drying conditions and the consequent buildup of deposits in the flue gas ducts, because the low temperatures at that point do not provide the evaporative driving force that is needed to quickly flash off the water.
Sodium compounds, such as the bisulfite, carbonate, bicarbonate and carbonate/bicarbonates (Trona) compounds, have also been injected into the cooler regions of the system to capture SO2, and are also effective in SO3 capture. However, they pose material handling, ash disposal, and potential deposit problems. They also tend to have poor utilization efficiencies, which are somewhat improved when they are ground to finer (−400 mesh) particle sizes. The relatively coarse particles are prone to form an outer sulfate shell, thereby inhibiting utilization of the unreacted chemical inside the shell. Additionally, grinding of such materials is expensive, and it creates storage and handling problems because of the fineness and hygroscopic nature of the particles. Ash disposal issues also arise because of the solubility of sodium compounds, and in some cases steps to insure containment in the disposal ponds may be required.
Commercially available, but relatively expensive, oil-based magnesium additives can be effective in SO3 capture. In that regard, one of the most effective chemical techniques for controlling both ash-related fouling in the boiler, and also the corrosion and emission problems associated with SO3 generated in solid-fueled boilers, is the injection into the upper region of the boiler of oil-based slurries of MgO or Mg(OH)2. That technology was originally developed for use with oil fired boilers, in which the magnesium-based oil suspension was usually metered into the fuel. It was later applied to coal-fired boilers. The most widely accepted mode of application of such additives today is by injection of slurries of MgO or Mg(OH)2 into the boiler just below the region at which a transition from radiant heat transfer to convective heat transfer occurs. Though very effective for SO3 capture when injected into the furnace, the magnesium compounds have no affinity for SO2, and they are therefore not very useful for scavenging SO2 within the furnace.
Although magnesium compounds are not effective for SO2 capture, calcium compounds can serve as effective scavengers of both SO2 and SO3. Because both of the alkaline earths can be helpful in dealing with fouling, the resulting magnesium sulfate deposits are more soluble than their calcium counterparts, and are therefore easier to remove. Thus, the magnesium compounds are more widely used for addressing slagging and fouling. The deposit removal advantage of the magnesium compounds is lost when the more effective calcium reagent for SOx scavenging is of very fine form, because more of the slag mitigating reactions take place within the flue gas stream than on the boiler tube surfaces.
Another approach that has been utilized for SO3 capture involves the use of so-called “overbased” organic-acid-neutralizing compounds of the type that are included as additives in motor oils and as fuel-oil-combustion additives. Those additives are actually colloidal dispersions of metallic carbonates, usually magnesium or calcium. When burned with fuel oil, they are effective at near stoichiometric dosage in capturing SO3 and in mitigating ash deposits caused by vanadium and/or sodium in the oil. The colloidal dispersions are stabilized by carboxylic or sulphonate compounds and are known to provide mostly particles in the Angstrom range. Though very expensive, the “overbased” compounds are widely used at low dosages to capture vanadium in heavy-oil-fired combustion turbines. They have been utilized in SO3 capture efforts, but there appear to have been no prior reports of their use for capturing either SO2 or toxic metals. Although emissions benefits can be obtained by the use of the so-called “overbased” compounds, their much higher cost and their combustibility make them a less attractive option for most applications. Additionally, the combustibility of the overbased materials requires hard piping as well as additional safety devices, each of which involves increased costs.
In addition to their use in oil-based slurries, Mg(OH)2 powders and water-based slurries have also been utilized as fireside additives in boilers, but because of their generally coarser particle size they are less efficient in capturing the SO3. Water slurries of MgO have also been injected through specially modified soot blowers installed on oil- and kraft-liquor-fired boilers, in which they moderated high temperature deposits but had only a nominal impact on SOx-related emissions because of an inability to apply the chemicals continuously.
In addition to regulations limiting SOx emissions, regulations aimed at limiting mercury emissions from coal-fired boilers have been promulgated by regulatory authorities, and proposed regulations applicable to the capture of other toxic metals are pending. A considerable amount of research aimed at finding practical techniques for capturing such toxic metals has shown that high-surface-area solids can capture a significant portion of mercury by adsorption, if the mercury is in an oxidized form rather than in an elemental form. Research was reported by Ghorishi, et al. (“Preparation and Evaluation of Modified Lime and Silica-Lime Sorbents for Mercury Vapor Emissions Control,” EPA Energy Citations Database, Document No. 698008, Nov. 1, 1999) relating to mercury capture utilizing calcium silicates and hydrated lime (Ca(OH)2). That research emphasized the necessity of extensive surface area for reaction, which was provided by fine pores in the sorbents, but it was focused on avoiding or minimizing pore closure of the sorbents by including suitable additives. It also noted that it was necessary to minimize the presence of SO2, because the SO2 competes with the Hg for the available capture surface of the sorbent, and when it is present the SO2 reduces the effectiveness of Hg capture.
Oxidants, either added to or naturally present in the fuel, such as chlorides, can facilitate the oxidation of the mercury. Although high-surface-area lime can be effective in mercury capture, the commercially-available powders can be difficult to consistently deliver into the boiler. They result in operational problems within the boiler in the form of ash deposits, and they can result in increased stack emissions because of the unfavorable electrical properties of any unreacted lime. To date, the most widely accepted way to achieve mercury capture has been the injection of expensive activated carbons into the cooler regions of the boiler gas path.
Combustion systems requiring additional emission control generally fall into two broad, size-based groups. The first group includes large systems that are sufficiently new and can economically justify the large capital investment needed for scrubbers for SO2 and for selective catalytic reactors (SCR's) for NOx. That first group commonly encounters problems in the form of SO3 plumes, because the scrubbers do not effectively capture that pollutant. Furnace Sorbent Injection (FSI) is a particularly useful option because it not only deals with the SO3 plume problem, but it also captures the arsenic that can damage the SCR catalyst, it enhances mercury capture, which would otherwise be inhibited by competition with SO2 for the available reactive surface area, it allows lowering the flue gas exit temperatures, which can boost energy efficiency, and it allows the scrubber to capture the greater quantities of SO2 in order to comply with ever tighter emissions standards.
The second group of combustion systems includes those systems that are older and smaller, for which scrubbers and/or SCR's are difficult to physically retrofit, and that involve a major capital investment that is often difficult to justify economically. In that second group of systems, SO2 emission regulations have been met by switching to more costly, lower-sulfur fuels, and, more recently, by utilizing market-based emissions credits. Combustion process modifications have also been used successfully to reduce NOx emissions, but the reduction is often insufficient to bring the systems into full compliance with the latest regulations.
As a result of combustion system modifications that are aimed at minimizing NOx formation, those older, smaller systems can also generate a byproduct ash that is higher in unburned carbon. The efficiency loss as a result of the increased unburned carbon is small, typically less than about 0.5% of the fuel carbon, but if the amount of unburned carbon in the ash is too high (>5% of the ash), the ash becomes unmarketable, thereby converting a potential revenue stream from the sale of ash into an expenditure for ash disposal. Considerable work has gone into efforts to optimize the burners of such systems, but with only limited success. The present inventor has published data showing a significant reduction in unburned carbon when a large number of fine magnesium oxide particles are produced by injecting submicron magnesia into the superheater region of the upper furnace, both with and without ash reinjection (“Effectiveness of Fireside Additives in Coal-Fired Boilers,” Power Engineering, pages 72-76, April 1978). The treatment rates were sufficient to treat only SO3, and similar results would be expected with similarly-sized calcium or aluminum compounds.
Some of the smaller, older combustion systems tend to use selective non-catalytic reduction (SNCR), which utilize reactions similar to those of the SCR's by using ammonia or an amine, but without the catalysts. Both of those control technologies result in a small amount of ammonia in the flue gas downstream of the SNCR or SCR systems, and the ammonia can react with the SO3 that results either from the combustion process or from catalysis by the SCR itself, to form low-melting-point ammonium bisulfate, which can foul air preheaters that are further downstream in the flue gas flow path. The ammonium bisulfate problem can be mitigated by the injection of fine calcium compounds upstream of the air heater.
Both groups of combustion systems are likely to be required to conform with additional regulations that require the capture of trace quantities of toxic metals. Despite gas scrubbing, the scrubber/SCR-equipped systems that utilize higher sulfur content fuels also face a new, stack-opacity problem that results from a doubling by the SCR's of the SO2 that is catalyzed to SO3 and is emitted as a visible, sulfuric acid mist plume. The acid mist in the flue gas also results in system operating problems by plugging and corroding lower temperature components of the system.
The sulfuric acid plume problem has resulted in major environmental public relations issues for utilities, as evidenced by American Electric Power Company's purchase of the town of Cheshire, Ohio, because of acid mist discharge issues from its SCR-equipped wet scrubbers. The U.S. Department of Energy has spent millions of dollars in testing various SO3 control techniques, and a variety of acid-neutralizing systems are being installed.
The SO3 mitigation systems utilize a variety of alkaline chemical compounds that are injected at various points in the flue gas path, typically between the furnace exit and the ESP inlet, to effect the acid neutralization outside of the furnace. Most of those chemicals, including Ca(OH)2, Mg(OH)2, Trona, and SBS (sodium bisulfite), are relatively coarse in particle size. The finest-sized particles tested reportedly have a median particle size of about 3 microns. However, those chemical products are difficult to deploy, they are utilized at high rates that are 3 to 12 multiples of stoichiometric, and their use involves significant costs. Although the use of furnace injection of those coarser particles as an emissions control vehicle has been evaluated extensively, most current installations feed chemicals for both SO2 and SO3 control in the cooler section of the system at a point downstream of the SCR's, either as powder slurries, or solutions.
It is likely that the remaining boiler systems and combustion systems without scrubbers will soon need to meet more stringent SO2 regulations or face early shutdown if a practical, low capital cost, moderate operating cost, pollution control system does not become available. Those same plants will soon also be required to capture mercury and other toxic metals, as well as to deal with more stringent SOx and year-round NOx emission limitations.
Considerable research has been conducted on techniques for capturing the toxic metal pollutants before they can escape from the combustion system and/or damage the SCR catalyst. That research has shown that the injection at various points in the boiler, including on the coal, at the furnace exit, and at the economizer outlet, of larger-sized minerals (−¾″ to −325 mesh), high-surface-area high-porosity particulate materials, such as specially modified CaO, silicates, MgO, or activated carbon, can help to capture most of the metals. Heavy metals (Hg, Se, and As) capture has been shown to be significant when lime is injected at the furnace exit (2000° F. to 2200° F. temperature region) at twice the sulfur stoichiometric ratio, even though the surface area of the injected materials is relatively modest, of the order of about 1 to 4 m2/gm or more, and even though competition exists for that same reagent/reactant surface area by the acid-forming gases. The current regulatory focus is on the capture of mercury, and the current user focus is on injection into the cooler regions of the boiler of expensive, high-surface-activated carbon. However, the adverse operating and environmental impacts of the other toxic metals likely will lead to emissions regulations affecting their discharge, and more research into suitable scavenging reagents.
With regard to the capture of toxic metals and SO3, the University of North Dakota Energy and Environmental Research Center reported that the tiny fraction, less than about 1.5%, of sub-micron size ash particles that are present in ash have been found to adsorb SO3 (“Formation and Chemical Speciation of Arsenic-, Chromium-, and Nickle-bearing Coal Combustion,” Fuel Processing Technology, vol 85, issues 6-7, pages 701-726, Jun. 15, 2004). It suggested that the fraction of those particles is important for controlling the SO3 problem. The addition of fine alkaline materials (under 5 microns) was also mentioned. Other workers have reported that ash will adsorb toxic metals, but its low surface area leads to poor capture efficiency.
SO2 control utilizing powdered limestone injection into the upper furnace region near the nose (2000° F. to 2200° F. temperature region), a technology known as LIMB (Limestone Injection Multistage Burner), has been investigated extensively since the 1970's. That work, summarized in a paper by Paul S. Nolan (“Flue Gas Desulfurization Technologies for Coal-Fired Power Plants,” paper presented at the Coal-Tech 2000 International Conference, Jakarta, Indonesia, Nov. 13-14, 2000) also reported the focus on injection of reagents into the upper furnace region, near the furnace outlet (circa 2000° F. to 2200° F.), of more-expensive lime hydrate instead of limestone for SO2 capture. Prior bench and pilot studies had concluded that the upper furnace region would be the location “where the sulfation reactions would be maximized,” and noted that that location involved the sacrificing of additional reagent-to-flue gas contact time in order to avoid sintering of the lime particles. However; the LIMB approach has not been widely implemented because treatment rates twice stoichiometric with −325 mesh limestone powders (typical mean particle size of about 20 microns) captured no more than about 40% of the SO2. The lime hydrate (about 12 micron median) was more effective, achieving about 65% SO2 capture as shown in FIG. 7 of the Nolan paper, but that level of performance required a significant investment in a humidification system, boosting both capital and operating costs in terms of the energy needed to evaporate significant volumes of H2O. It also dramatically increased the ash burden, by as much as double, and it posed deposit problems in the boiler convective pass requiring near-continuous operation of the soot blowers. It also overburdened the electrostatic particulate control devices because of the poor electrical properties of the unreacted lime.
Much of the previous research effort focused on the creation of high-porosity, high-surface-area CaO particles by flash calcination of the limestone in the upper furnace region. The failure to achieve the desired improvement in chemical utilization efficiency without introducing humidification has been attributed by EPA researchers to sintering of the CaO particles, but the current inventor's results of his testing, as viewed with a scanning electron microscope, suggest that the low utilization efficiency is most likely due to plugging of the pores of the high-porosity particles with CaSO4, thereby reducing the accessible surface area for reaction and leaving a core of unreacted CaO. Some work with particle sizes in the 5 micron range has been reported, but that approach also has not been utilized commercially because of what is likely also to be a pore-plugging problem.
Thus far, the focus by others has been on adding excessive amounts of ground limestone (−325 mesh) having a median particle size of around 20 microns. The reason for that focus is that limestone is inexpensive, and even if one were to desire smaller particles, the normal mechanical size reduction techniques, such as grinding, for providing fine particle sizes, have all been judged by those facing the emission problem to be too expensive and economically unjustifiable.
Some research has been conducted on what might be described as a multi-pollutant control process, simulating the furnace injection of calcium and magnesium compounds slurried in solutions of nitrogen compounds. Theoretically, the combination would address all the emission issues except CO2. Although the injection of nitrogen solutions to control NOx is in wide use on power boilers, the combination with calcium slurries for simultaneous SO2 capture has not been commercially adopted. Reportedly, the failure to do so is the result of problems with settling and plugging in the slurry injection systems. To be effective, the NOx control systems inject the ammonia reagents near the nose of the furnace outlet, which is in the same temperature region called for by previous work using lime/limestone injection.
Reducing CO2 emissions has thus far not been the subject of regulations in much of the world. Emphasis has been placed on improving efficiency of fuel use. And research on sequestering the CO2 is ongoing, with some CO2 captured, liquefied, and used in enhancing oil recovery. Most of the commercial SOx emissions control processes for fossil-fueled combustion systems employ limestone (directly or as lime) with the net result being a significant secondary emission of CO2. The scrubbers employing limestone on the larger, newer units are the lowest emitters (about 0.7 tons CO2/ton of SO2 captured) while those using lime have net emissions at least twice as high because of the thermal loss in the calciners. Because the utilization of the limestone is so poor with conventional Furnace Sorbent Injection (FSI), the CO2 released per ton of SO2 captured is nearly 14 tons/per ton.
It is therefore an object of the present invention to provide improved multi-pollutant control processes while enhancing boiler operating conditions and efficiency.